HNRG 10-Q Quarterly Report June 30, 2025

HALLADOR ENERGY CO

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HALLADOR ENERGY CO_June 30, 2025

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2025

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-34743

HALLADOR ENERGY CO MPANY

( www.halladorenergy.com )


Colorado	84-1014610
(State of incorporation)	(IRS Employer Identification No.)

1183 East Canvasback Drive , Terre Haute , Indiana	47802
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 812 . 299.2800

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Shares, $.01 par value	HNRG	Nasdaq

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☐		Accelerated filer ☑
Non-accelerated filer ☐		Smaller reporting company ☑
		Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of August 7, 2025, we had 43,010,230 shares of common stock outstanding.

Table of Contents

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION	1

ITEM 1. FINANCIAL STATEMENTS (Unaudited)	1

Condensed Consolidated Balance Sheets	1

Condensed Consolidated Statements of Operations	2

Condensed Consolidated Statements of Cash Flows	3

Condensed Consolidated Statements of Stockholders’ Equity	4

Notes to Condensed Consolidated Financial Statements	5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	21

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33

ITEM 4. CONTROLS AND PROCEDURES	33

PART II - OTHER INFORMATION	35

ITEM 4. MINE SAFETY DISCLOSURES	35

ITEM 6. EXHIBITS	35

SIGNATURES	36

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Hallador Energy Company

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

(unaudited)


	June 30,		December 31,
	2025		2024
ASSETS
Current assets:
Cash and cash equivalents	$	9,228	$	7,232
Restricted cash		23,142		4,921
Accounts receivable		18,742		15,438
Inventory		43,570		36,685
Parts and supplies		42,755		39,104
Prepaid expenses		2,437		1,478
Total current assets		139,874		104,858
Property, plant and equipment:
Land and mineral rights		70,307		70,307
Buildings and equipment		446,278		429,857
Mine development		96,764		92,458
Finance lease right-of-use assets		13,034		13,034
Total property, plant and equipment		626,383		605,656
Less - accumulated depreciation, depletion and amortization		( 363,704 )		( 347,952 )
Total property, plant and equipment, net		262,679		257,704
Equity method investments		2,889		2,607
Other assets		4,071		3,951
Total assets	$	409,513	$	369,120

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net	$	17,139	$	4,095
Accounts payable and accrued liabilities		51,952		44,298
Current portion of lease financing		7,229		6,912
Contract liabilities - current		132,935		97,598
Total current liabilities		209,255		152,903
Long-term liabilities:
Bank debt, net		26,000		37,394
Long-term lease financing		5,052		8,749
Asset retirement obligations		15,822		14,957
Contract liabilities - long-term		29,216		49,121
Other		2,015		1,711
Total long-term liabilities		78,105		111,932
Total liabilities		287,360		264,835
Commitments and contingencies (Note 16)
Stockholders' equity:
Preferred stock, $ .10 par value, 10,000 shares authorized; none issued		—		—
Common stock, $ .01 par value, 100,000 shares authorized; 42,978 and 42,621 issued and outstanding, as of June 30, 2025 and December 31, 2024, respectively		430		426
Additional paid-in capital		188,935		189,298
Retained deficit		( 67,212 )		( 85,439 )
Total stockholders’ equity		122,153		104,285
Total liabilities and stockholders’ equity	$	409,513	$	369,120

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
SALES AND OPERATING REVENUES:
Electric sales	$	59,976	$	59,979	$	145,919	$	120,880
Coal sales		38,147		32,801		68,332		82,431
Other revenues		4,766		1,045		6,425		2,308
Total sales and operating revenues		102,889		93,825		220,676		205,619
EXPENSES:
Fuel		15,063		12,370		30,273		20,929
Other operating and maintenance costs		28,955		33,981		57,344		70,963
Cost of purchased power		2,172		2,619		9,012		4,545
Utilities		4,507		3,910		8,659		8,504
Labor		26,799		26,555		53,828		61,723
Depreciation, depletion and amortization		5,542		13,649		20,519		29,092
Asset retirement obligations accretion		437		399		864		798
Exploration costs		98		47		119		117
General and administrative		7,501		7,803		14,326		13,747
Gain on disposal or abandonment of assets, net		( 55 )		( 222 )		( 76 )		( 246 )
Total operating expenses		91,019		101,111		194,868		210,172

INCOME (LOSS) FROM OPERATIONS		11,870		( 7,286 )		25,808		( 4,553 )

Interest expense (1)		( 3,819 )		( 3,735 )		( 7,542 )		( 7,672 )
Loss on extinguishment of debt		—		( 1,937 )		—		( 2,790 )
Equity method investment (loss)		197		( 257 )		( 39 )		( 506 )
NET INCOME (LOSS) BEFORE INCOME TAXES		8,248		( 13,215 )		18,227		( 15,521 )

INCOME TAX BENEFIT:
Current		—		—		—		—
Deferred		—		( 3,011 )		—		( 3,621 )
Total income tax benefit		—		( 3,011 )		—		( 3,621 )

NET INCOME (LOSS)	$	8,248	$	( 10,204 )	$	18,227	$	( 11,900 )

NET INCOME (LOSS) PER SHARE:
Basic	$	0.19	$	( 0.27 )	$	0.43	$	( 0.32 )
Diluted	$	0.19	$	( 0.27 )	$	0.42	$	( 0.32 )

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		42,619		37,879		42,798		37,026
Diluted		43,048		37,879		43,434		37,026

(1) Interest Expense:
Interest on bank debt	$	1,404	$	2,779	$	2,898	$	5,584
Other interest		1,891		547		3,623		1,275
Amortization of debt issuance costs		524		409		1,021		813
Total interest expense	$	3,819	$	3,735	$	7,542	$	7,672

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)


	Six Months Ended June 30,
	2025		2024
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	18,227	$	( 11,900 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax (benefit)		—		( 3,621 )
Equity method investment loss		39		506
Depreciation, depletion and amortization		20,519		29,092
Loss on extinguishment of debt		—		2,790
Gain on disposal or abandonment of assets, net		( 76 )		( 246 )
Amortization of debt issuance costs		1,021		813
Asset retirement obligations accretion		864		798
Cash paid on asset retirement obligation reclamation		( 311 )		( 602 )
Stock-based compensation		1,559		2,247
Amortization of contract liabilities		( 65,597 )		( 46,524 )
Accretion on contract liabilities		3,215		—
Other		284		1,402
Change in current assets and liabilities:
Accounts receivable		( 3,304 )		839
Inventory		( 6,885 )		( 9,520 )
Parts and supplies		( 3,651 )		( 582 )
Prepaid expenses		1,003		2,140
Accounts payable and accrued liabilities		5,062		( 11,107 )
Contract liabilities		77,814		83,366
Net cash provided by operating activities	$	49,783	$	39,891
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	$	( 24,737 )	$	( 28,044 )
Proceeds from sale of equipment		162		2,474
Investment in equity method investments		( 322 )		—
Net cash used in investing activities		( 24,897 )		( 25,570 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt		( 44,000 )		( 86,500 )
Borrowings of bank debt		45,000		40,500
Payments on lease financing		( 3,421 )		( 2,665 )
Proceeds from sale and leaseback arrangement		—		3,783
Issuance of related party notes payable		—		5,000
Payments on related party notes payable		—		( 5,000 )
Debt issuance costs		( 330 )		( 76 )
ATM offering		—		34,515
Taxes paid on vesting of RSUs		( 1,918 )		( 273 )
Net cash used in financing activities		( 4,669 )		( 10,716 )
Increase in cash, cash equivalents, and restricted cash		20,217		3,605
Cash, cash equivalents, and restricted cash, beginning of period		12,153		7,123
Cash, cash equivalents, and restricted cash, end of period	$	32,370	$	10,728
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents	$	9,228	$	6,446
Restricted cash		23,142		4,282
	$	32,370	$	10,728
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	2,768	$	6,312
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense	$	843	$	( 1,694 )
Stock issued on redemption of convertible notes and interest	$	—	$	22,993

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(unaudited)


				Additional				Total
	Common Stock Issued			Paid-in		Retained		Stockholders’
	Shares	Amount		Capital		Deficit		Equity
Balance, March 31, 2025	42,978	$	430	$	190,378	$	( 75,460 )	$	115,348
Stock-based compensation	—		—		475		—		475
Taxes paid on vesting of RSUs	—		—		( 1,918 )		—		( 1,918 )
Net Income	—		—		—		8,248		8,248
Balance, June 30, 2025	42,978	$	430	$	188,935	$	( 67,212 )	$	122,153

Balance, December 31, 2024	42,621	$	426	$	189,298	$	( 85,439 )	$	104,285
Stock-based compensation	—		—		1,559		—		1,559
Stock issued on vesting of RSUs	513		5		( 5 )		—		—
Taxes paid on vesting of RSUs	( 156 )		( 1 )		( 1,917 )		—		( 1,918 )
Net Income	—		—		—		18,227		18,227
Balance, June 30, 2025	42,978	$	430	$	188,935	$	( 67,212 )	$	122,153


				Additional				Total
	Common Stock Issued			Paid-in		Retained		Stockholders’
	Shares	Amount		Capital		Earnings		Equity
Balance, March 31, 2024	36,534	$	365	$	144,490	$	139,003	$	283,858
Stock-based compensation	—		—		1,581		—		1,581
Stock issued on vesting of RSUs	58		1		( 1 )		—		—
Taxes paid on vesting of RSUs	( 27 )		( 1 )		( 271 )		—		( 272 )
Stock issued on redemption of convertible notes	2,090		21		13,251		—		13,272
Stock issued in ATM offering	3,944		40		27,895		—		27,935
Net loss	—		—		—		( 10,204 )		( 10,204 )
Balance, June 30, 2024	42,599	$	426	$	186,945	$	128,799	$	316,170

Balance, December 31, 2023	34,052	$	341	$	127,548	$	140,699	$	268,588
Stock-based compensation	—		—		2,247		—		2,247
Stock issued on vesting of RSUs	379		4		( 4 )		—		—
Taxes paid on vesting of RSUs	( 159 )		( 2 )		( 271 )		—		( 273 )
Stock issued on redemption of convertible notes	3,672		36		22,957		—		22,993
Stock issued in ATM offering	4,655		47		34,468		—		34,515
Net loss	—		—		—		( 11,900 )		( 11,900 )
Balance, June 30, 2024	42,599	$	426	$	186,945	$	128,799	$	316,170

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Notes to Condensed Consolidated Financial Statements

(unaudited)

(1)	GENERAL BUSINESS

The condensed consolidated financial statements include the accounts of Hallador Energy Company (hereinafter known as “we, us, or our”) and its wholly owned subsidiaries Hallador Power Company, LLC (“Hallador Power”), Sunrise Coal, LLC (“Sunrise”), and Hourglass Sands, LLC (“Hourglass”), as well as Hallador Power and Sunrise’s wholly owned subsidiaries.

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.

In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50 % interest in Sunrise Energy, LLC (“Sunrise Energy”), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.

The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant (“Merom”).

The Coal Operations reportable segment includes our currently operating underground mining complex Oaktown 1. We have other mining complexes and locations which were idled during the year ended December 31, 2024.

All significant intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the Company’s prior period condensed consolidated financial information to conform to the current period presentation. These presentation changes did not impact the Company’s condensed consolidated net income (loss), consolidated cash flows, total assets, total liabilities or total stockholders’ equity.

The interim financial data is unaudited; however, in our opinion, it includes all adjustments, consisting only of normal recurring adjustments necessary for a fair statement of the results for the interim periods. The condensed consolidated financial statements included herein have been prepared pursuant to the Securities and Exchange Commission’s (the “SEC”) rules and regulations; accordingly, certain information and footnote disclosures normally included in generally accepted accounting principles (“GAAP”) financial statements have been condensed or omitted.

The results of operations and cash flows for the three and six months ended June 30, 2025, are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2025.

Our organization and business, the accounting policies we follow, and other information are contained in the notes to our consolidated financial statements filed as part of our 2024 Annual Report on Form 10-K . This quarterly report should be read in conjunction with such Annual Report on Form 10-K.

(2)	RECENT ACCOUNTING PRONOUNCEMENTS

Recent Accounting Pronouncements - Adopted

For the year ended December 31, 2024, the Company retrospectively adopted Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ("ASU 2023-07"). See “ Note 14 – Segments of Business ” for enhanced disclosures associated with the adoption of ASU 2023-07.

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Recent Accounting Pronouncements – Not Yet Adopted

In December 2023, the Financial Accounting Standards Board ("FASB") issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-09, but do not expect it to have a material effect on our consolidated financial statements.

In November 2024, the FASB issued ASU 2024-04, Debt - Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversion of Convertible Debt Instruments. The objective of the standard is to improve the relevance and consistency in application of the induced conversion guidance in Subtopic 470-20, Debt with Conversion and Other Options. This standard will affect entities that settle convertible debt instruments for which the conversion privileges are changed to induce conversion. The guidance will be effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting-Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its financial statement disclosures.

(3)	LONG-LIVED ASSET IMPAIRMENTS

During the year ended December 31, 2024, the Company recorded a $ 215.1 million non-cash impairment charge in our Coal Operations segment due to the results of our annual business plan review. As part of that business plan review, the Company evaluated core hole samples at several of our mines, noting the samples obtained at our Oaktown 2 mine were determined to be of a lower quality and density than that of the Oaktown 1 mine. As such, the Company decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs.

The fair values of the impaired assets were determined using a discounted cash flow model, which represents Level 3 fair value measurements under the fair value hierarchy. The fair value analysis used assumptions regarding the projected economics of the Coal Operations assets, given prevailing commodity prices and operating expense levels.

For the three and six months ended June 30, 2025, no impairment charges were recorded for long-lived assets.

(4)

INVENTORY

Inventory is valued at a lower of cost or net realizable value (NRV). As of June 30, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $ 0.1 million and $ 0.3 million, respectively.

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(5)

BANK DEBT

On June 27, 2025, the Company executed the Third Amendment (“Third Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC Bank, National Association (in its capacity as administrative agent, "PNC"), which was accounted for as a debt modification. The primary purpose of the Third Amendment was to provide additional operating flexibility for the remainder of 2025 by redefining covenants, deferring certain covenants until the third quarter of 2025 and moving our October 2025 payment to January 2026. The Third Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company maintains one hundred percent of the outstanding aggregate principal balance of the Credit Agreement (“Term Loan”) as a compensating balance. During the second quarter of 2025, the Company entered into a $ 35.0 million prepaid forward power sales contract, as noted in “Note 7 – Revenue” of which $ 19.0 million of the proceeds were deposited into a money market account with the administrative agent. The compensating balance is classified as “restricted cash” on the condensed consolidated balance sheets at June 30, 2025. As part of the Third Amendment, the required October 2025 principal payment of $ 6.0 million and the January 2026 principal payment of $ 6.5 million, pursuant to the Term Loan, are both now due in January 2026. The balance of the Term Loan will be fully repaid no later than March 2026. All payments will be funded by withdrawals from our compensating balance held in our money market account. Furthermore, the Third Amendment defines certain administrative changes which include, among other things modifications to the required timelines related to reporting and the removal of third-party financial advisors.

Bank debt increased by $ 1.0 million during the six months ended June 30, 2025. Bank debt totaled $ 45.0 million and is comprised of our Term Loan ( $ 19.0 million as of June 30, 2025) and a $ 75.0 million revolver ( $ 26.0 million borrowed as of June 30, 2025) under the Credit Agreement. Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.

Liquidity

As of June 30, 2025, we had additional borrowing capacity of $ 32.8 million under the revolver and total liquidity of $ 42.0 million. Our additional borrowing capacity is net of $ 16.2 million in outstanding letters of credit as of June 30, 2025 that were required to maintain surety bonds and other credit support obligations . Liquidity consists of our additional borrowing capacity and cash and cash equivalents.

The Company is currently in discussions with members of its existing bank group and other lenders to refinance our current Credit Agreement. The revolving credit facility matures July 31, 2026 and our Term Loan matures March 31, 2026. The balance of the Term Loan is scheduled to be repaid in January 2026 and March 2026, utilizing restricted cash as set forth in the Third Amendment. As such, the Term Loan is listed as current on the June 30, 2025 condensed consolidated balance sheet. While no definitive agreement has been reached as of the reporting date, management believes it is probable that the Credit Agreement will be refinanced on market terms and conditions for similar situated borrowers and consistent with the existing Credit Agreement. However, there can be no assurance that such efforts will be successful or completed on favorable terms. Failure to refinance our Credit Agreement debt prior to maturity could adversely affect the Company’s liquidity and financial condition.

Fees

Unamortized bank fees and other costs incurred in connection with our initial facility totaled $ 4.3 million. Additional costs incurred with our Debt Agreement amendments totaled $ 0.9 million, of which $ 0.3 million related to our Third Amendment . These unamortized bank fees were deferred and are being amortized over the term of the loan. Unamortized bank fees as of June 30, 2025, and December 31, 2024, were $ 1.9 million and $ 2.5 million, respectively. Unused borrowing capacity under the facility was $ 32.8 million as of June 30, 2025. Commitment fees on the unused portion of the facility are 0.50 % per annum.

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Bank debt, less debt issuance costs, is presented below (in thousands):


	June 30,		December 31,
	2025		2024
Current bank debt	$	19,000	$	6,000
Less unamortized debt issuance cost		( 1,861 )		( 1,905 )
Net current portion	$	17,139	$	4,095

Long-term bank debt	$	26,000	$	38,000
Less unamortized debt issuance cost		—		( 606 )
Net long-term portion	$	26,000	$	37,394

Total bank debt	$	45,000	$	44,000
Less total unamortized debt issuance cost		( 1,861 )		( 2,511 )
Net bank debt	$	43,139	$	41,489


Future Maturities (in thousands):
2025	$	—
2026		45,000
Total	$	45,000

Covenants

The Third Amendment, among other things, deferred the Maximum Leverage Ratio and Minimum Debt Service Coverage Ratios until September 2025. The Maximum Leverage Ratio requirement was changed to 3.00 to 1.00 for our fiscal quarter ending September 30, 2025, and is 2.25 to 1.00 thereafter. The Debt Service Coverage Ratio requirement was changed to 3.25 to 1.00 as long as the Company maintains the required compensating balance, if not, remains at 1.25 to 1.00. The Third Amendment removed the First Lien Leverage Ratio while maintaining the minimum liquidity requirement of $ 10.0 million, as defined in the First Amendment to the Credit Agreement.

As of June 30, 2025, we were in compliance with all other covenants defined in the Credit Agreement.

Interest Rate

The interest rate on the facility ranges from secured overnight financing rate (“SOFR”) plus 4.00 % to SOFR plus 5.00 %, depending on our Leverage Ratio. As of June 30, 2025, we were paying SOFR plus 5.00 % on the outstanding bank debt which equates to an all-in rate of 9.43 %.

(6)	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consist of the following for the indicated dates (in thousands):


	June 30,		December 31,
	2025		2024
Accounts payable	$	31,442	$	24,291
Accrued property taxes		3,832		4,185
Accrued payroll		5,038		3,258
Workers' compensation reserve		5,306		4,321
Group health insurance		1,600		1,700
Asset retirement obligation - current portion		1,542		1,952
Other		3,192		4,591
Total accounts payable and accrued liabilities	$	51,952	$	44,298

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(7)

REVENUE

Revenue from Contracts with Customers

We account for a contract with a customer when the parties have executed the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all the consideration will be collected. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer.

Electric operations

We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), is met at the time a PPA is executed by the parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.

We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract capacity performance obligations and daily, based on an output method of MWh of electricity delivered.

For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier. For delivered energy to all other customers, we recognize revenue daily for the actual delivered electricity.

When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market. We record these as “cost of purchased power” on our condensed consolidated statements of operations.

Coal operations

Our coal revenue is derived from sales to customers of coal produced at our facilities. Our customers typically purchase coal directly from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.

Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as Btu factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.

Disaggregation of Revenue

Revenue is disaggregated by revenue source for our electric operations and by primary geographic markets for our coal operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors.

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Electric operations


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Delivered energy (including contract liability amortization)	$	44,132	$	43,106	$	116,268	$	92,234
Capacity		15,844		16,873		29,651		28,646
Total Electric Operations sales	$	59,976	$	59,979	$	145,919	$	120,880

Coal operations


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Outside third-party Indiana customers	$	21,290	$	15,048	$	41,604	$	33,152
Customers in Florida, North Carolina, Alabama and Georgia		16,857		17,753		26,728		49,279
Total Coal Operations sales	$	38,147	$	32,801	$	68,332	$	82,431

Performance Obligations

Electric Operations

We concluded that each megawatt hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the customer.

During the second quarter of 2025, we entered into a 17-month , $ 35.0 million prepaid physically delivered power contract in which Hallador will provide a total of 971,088 MWh to be delivered at various periods starting in July 2025 through November 2026. As the total amount paid up-front by the customer differs from the stand-alone selling price of the transferred power, the Company concluded the contract contains a significant financing component. The contract liability associated with the $ 35.0 million prepayment will be accreted over the agreement term based upon the Company’s incremental borrowing rate which approximates 9.50 %, and the accretion will be separately recognized as interest expense.

Coal Operations

A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.

The following table illustrates the balance of all current Electric and Coal Operations contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2025 and disaggregated by segment and contract duration.


	2025		2026		2027		2028		2029		Total
Delivered energy revenues	$	95,510	$	172,220	$	97,280	$	57,750	$	13,770	$	436,530
Capacity revenues		29,460		61,540		51,400		37,330		3,470		183,200
Coal Operations revenues		72,360		127,830		141,850		29,500		—		371,540
Total revenue (1)	$	197,330	$	361,590	$	290,530	$	124,580	$	17,240	$	991,270

(1) Coal revenues consist of consolidated revenues excluding our intercompany revenues from Merom .

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Contract Balances

Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.

Under the typical payment terms of our contracts with customers, the customer pays us the contracted price for electricity or capacity. For coal contracts, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our condensed consolidated balance sheets. Payments received prior to fulfilling our performance obligations are included in contract liabilities in our condensed consolidated balance sheets.

The following table shows our beginning and ending accounts receivable from contracts with customers balance for the periods presented (in thousands):


	June 30,
	2025		2024
Accounts receivable from contracts with customers - beginning balance	$	15,438	$	19,937
Accounts receivable from contracts with customers - ending balance	$	18,742	$	19,098

As the Company fulfills its contractual obligations, we recognized those amounts in revenues. The following table reconciles our beginning and ending contract liabilities for the periods presented (in thousands):


	June 30,
	2025		2024
Total contract liabilities - beginning balance	$	146,719	$	113,741
Cash payments received on future contract obligations		82,476		90,082
Accretion on contract liabilities		3,215		—
Revenue recognized, cash payment received in prior period		( 65,597 )		( 46,524 )
Revenue recognized, cash payment received in current period		( 4,662 )		( 6,716 )
Total contract liabilities - ending balance	$	162,151	$	150,583

(8)	INCOME TAXES

For the six months ended June 30, 2025 and 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. The effective tax rate for the six months ended June 30, 2025 and 2024, was ~ 0 % due to recording of a full valuation allowance and ~ 23 %, respectively. Historically, our actual effective tax rates have differed from the statutory effective rate primarily due to the benefit received from statutory percentage depletion in excess of tax basis. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

(9)	STOCK COMPENSATION PLANS


Non-vested grants as of December 31, 2024		1,034,486
Vested - weighted average share price on vested date was $ 12.28		( 513,068 )
Forfeited		( 9,500 )
Non-vested grants as of June 30, 2025		511,918

For the three and six months ended June 30, 2025, our stock compensation expense was $ 0.5 million and $ 1.6 million, respectively. For the three and six months ended June 30, 2024, our stock compensation expense was $ 1.6 million and $ 2.2 million, respectively.

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Non-vested RSU grants will vest as follows:


Vesting Year		RSUs Vesting
2025		159,500
2026		176,210
2027		176,208
		511,918

The outstanding RSUs have a value of $ 8.1 million based on the June 30, 2025 closing stock price of $ 15.83 .

As noted in our Form 8-K filed with the SEC on June 2, 2025, on May 29, 2025, shareholders approved the Second Amended and Restated 2008 Restricted Stock Unit Plan (the “RSU Plan”) which, (i) increased the number of shares available for issuance by 2,000,000 shares, and (ii) extended the term of the RSU Plan until May 29, 2035.

As of June 30, 2025, unrecognized stock compensation expense to be recognized over the rolling 3 -year vesting period is $ 1.0 million, and we had 2,219,819 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities. Forfeitures are recognized as they occur.

(10)	SELF-INSURANCE

The Company is self-insured for certain risks, including physical damage and operational liability, related to our non-leased underground mining equipment allocated among four mining units dispersed over seven miles. The Company records a liability for self-insured risks when a loss is both probable and reasonably estimable. The Company had no accrual for self-insurance liabilities as of June 30, 2025 or December 31, 2024.

The Company also self-insures for workers’ compensation claims under a guaranteed cost program. Under this program, the Company is responsible for the first $ 1.0 million per claim up to an aggregate of $ 4.0 million annually. The Company has restricted cash of $ 23.1 million and $ 3.4 million as of June 30, 2025, and December 31, 2024, respectively, which represents cash held and controlled by third parties and is restricted primarily for future workers’ compensation claim payments and the $ 19.0 million compensating balance on our Term Loan (as discussed in “Note 5 – Bank Debt” above). The Company had $ 5.3 million and $ 4.3 million of workers’ compensation reserve as of June 30, 2025 and December 31, 2024 , respectively, in “accounts payable and accrued liabilities” on the condensed consolidated balance sheets.

(11)	FAIR VALUE MEASUREMENTS

We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. We have no Level 2 instruments.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair value measures .

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Nonrecurring Fair Value Measurements

During the fourth quarter of 2024, the Company completed its review of the coal mining facilities and future mining plans. The impairment analysis was based upon the coal mining operating plans of the Company, market driven pricing and cost trends. As part of that analysis, the Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $ 215.1 million in 2024.

The discounted cash flow model was calculated using projected economics for the Coal Operations assets, using the Company’s mining plan and reserve estimates to be mined and sold at prevailing commodity prices, operating expenses, and production cost levels, which are classified as Level 3 inputs.

Credit Risk

The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.

The Company’s cash and cash equivalent and restricted cash balances on deposit with financial institutions total $ 32.4 million and $ 12.2 million as of June 30, 2025 and December 31, 2024, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. The Company utilizes large and reputable banking institutions which it believes mitigates these risks. The Company has not experienced any losses in such accounts.

(12)	EQUITY METHOD INVESTMENTS

We own a 50 % interest in Sunrise Energy, LLC, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy, LLC, also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. The carrying value of the investment included in our condensed consolidated balance sheets as of June 30, 2025, and December 31, 2024, was $ 2.2 million and $ 2.1 million, respectively.

The Company also owns a 50 % interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value of the investment included in the condensed consolidated balance sheets as of June 30, 2025, and December 31, 2024, was $ 0.7 million and $ 0.5 million, respectively.

(13)	ORGANIZATIONAL RESTRUCTURING

On February 23, 2024, (the “Effective Date”), we committed to a reorganization effort in the Coal Operations Segment (the “Reorganization Plan”) that included a workforce reduction of approximately 110 employees, or approximately 12 % of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Reorganization Plan was designed to strengthen our financial and operational efficiency and create significant operational savings and higher margins in our Coal Operations segment. This step helped advance our transition from a company primarily focused on coal production to a more resilient and diversified integrated independent power producer (“IPP”). As part of this initiative, we substantially idled production at our higher cost surface mines, Prosperity Mine and Freelandville Mine, with minimal ongoing production. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. In connection with the Reorganization Plan, we incurred aggregate expenses of $ 1.9 million ($ 1.1 million in the first quarter of 2024 and $ 0.8 million in the second quarter of 2024) that were included in “labor” in the condensed consolidated statements of operations. These charges related to compensation, tax, professional, and insurance related expenses are considered one-time charges paid during 2024. The coal mining properties asset group was tested for impairment as result of the organizational restructuring passing the undiscounted recoverability test.

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(14)	SEGMENTS OF BUSINESS

Our Electric Operations segment includes the electric power generation facilities of our Merom power plant, which is a two unit, 1080 -megawatt rated coal fired power plant located in Sullivan County, Indiana. Our sales region is in MISO Zone 6, which includes Indiana and a portion of western Kentucky. Revenues from our Electric Operations segment consist primarily of delivered energy and capacity revenues. Fuel costs included in our Electric Operations segment include the cost of coal purchased from our Coal Operations segment, which are based on multi-year contracts which approximate market prices at the time the contracts are entered into.

Our Coal Operations segment includes the Oaktown 1 underground mining complex, as well as other currently idled mining facilities, which produce high-quality bituminous coal from the Illinois Basin. Revenues from our Coal Operations segment consist of sales of coal to various third-parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts which approximate market prices at the time the contracts are entered into. Intercompany coal sales and amounts above actual costs to produce the coal are eliminated in the consolidated statements of operations.

The CODM evaluates segment performance based upon EBITDA margin for each business segment. EBITDA margin is calculated for each segment as follows:

For our Electric Operations segment, EBITDA margin is comprised of delivered energy revenues less certain significant segment expenses, which include (i) variable costs, (ii) other operating and maintenance costs, (iii) costs of purchased power, (iv) utilities, (v) labor and (vi) general and administrative costs. (i) Variable operating costs are comprised of fuel costs and certain other operating costs, such as limestone and soda ash.

For our Coal Operations segment, EBITDA margin is comprised of coal sales less certain significant segment expenses, which include (i) fuel, (ii) other operating and maintenance costs, (iii) utilities, (iv) labor and (v) general and administrative costs.

EBITDA margin for each segment is a key measure used by our CODM and provides information about our core operating performance, significant expenses and ability to generate cash flow. Additionally, EBITDA margin provides investors with the financial analytical framework upon which our CODM bases financial, operational, compensation and planning decisions and presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations. Our CODM reviews variable costs, as defined above, in our Electric Operations segment in order to evaluate the efficiency of that segments operations.

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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended June 30, 2025 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	44,132	Coal Sales	$	45,529
Capacity Revenue		15,844
Electric Sales	$	59,976

Fuel	$	( 21,328 )
Other Operating Costs (1)		( 1 )
Total Variable Costs	$	( 21,329 )

Other Operating and Maintenance Costs (2)	$	( 10,707 )	Fuel	$	( 434 )
Cost of Purchased Power		( 2,172 )	Other Operating and Maintenance Costs		( 18,247 )
Utilities		( 1,383 )	Utilities		( 3,124 )
Labor		( 7,639 )	Labor		( 19,160 )
Power Margin Without General and Administrative		16,746	Coal Margin Without General and Administrative		4,564
General and Administrative		( 1,129 )	General and Administrative		( 1,915 )
Electric Operations — EBITDA Margin	$	15,617	Coal Operations — EBITDA Margin	$	2,649

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended June 30, 2024 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	43,106	Coal Sales	$	45,710
Capacity Revenue		16,873
Electric Sales	$	59,979

Fuel	$	( 24,416 )
Other Operating Costs (1)		7
Total Variable Costs	$	( 24,409 )

Other Operating and Maintenance Costs (2)	$	( 12,479 )	Fuel	$	( 750 )
Cost of Purchased Power		( 2,619 )	Other Operating and Maintenance Costs		( 21,597 )
Utilities		( 437 )	Utilities		( 3,253 )
Labor		( 7,160 )	Labor		( 19,395 )
Power Margin Without General and Administrative		12,875	Coal Margin Without General and Administrative		715
General and Administrative		( 1,450 )	General and Administrative		( 3,492 )
Electric Operations — EBITDA Margin	$	11,425	Coal Operations — EBITDA Margin	$	( 2,777 )

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the six months ended June 30, 2025 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	116,268	Coal Sales	$	100,303
Capacity Revenue		29,651
Electric Sales	$	145,919

Fuel	$	( 59,399 )
Other Operating Costs (1)		( 9 )
Total Variable Costs	$	( 59,408 )

Other Operating and Maintenance Costs (2)	$	( 15,234 )	Fuel	$	( 990 )
Cost of Purchased Power		( 9,012 )	Other Operating and Maintenance Costs		( 42,101 )
Utilities		( 2,059 )	Utilities		( 6,600 )
Labor		( 15,782 )	Labor		( 38,046 )
Power Margin Without General and Administrative		44,424	Coal Margin Without General and Administrative		12,566
General and Administrative		( 2,664 )	General and Administrative		( 4,228 )
Electric Operations — EBITDA Margin	$	41,760	Coal Operations — EBITDA Margin	$	8,338

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the six months ended June 30, 2024 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	92,234	Coal Sales	$	111,746
Capacity Revenue		28,646
Electric Sales	$	120,880

Fuel	$	( 49,351 )
Other Operating Costs (1)		14
Total Variable Costs	$	( 49,337 )

Other Operating and Maintenance Costs (2)	$	( 17,365 )	Fuel	$	( 1,985 )
Cost of Purchased Power		( 4,545 )	Other Operating and Maintenance Costs		( 53,388 )
Utilities		( 959 )	Utilities		( 7,545 )
Labor		( 14,843 )	Labor		( 46,880 )
Power Margin Without General and Administrative		33,831	Coal Margin Without General and Administrative		1,948
General and Administrative		( 2,508 )	General and Administrative		( 5,930 )
Electric Operations — EBITDA Margin	$	31,323	Coal Operations — EBITDA Margin	$	( 3,982 )

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended June 30, 2025 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	44,132	$	—	$	—	$	44,132
Capacity Revenue		15,844		—		—		15,844
Other Operating Revenue		3,134		1,399		233		4,766
Coal Sales (Third-Party)		—		38,147		—		38,147
Coal Sales (Intercompany)		—		7,382		( 7,382 )		—
Operating Revenues	$	63,110	$	46,928	$	( 7,149 )	$	102,889

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended June 30, 2024 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	43,106	$	—	$	—	$	43,106
Capacity Revenue		16,873		—		—		16,873
Other Operating Revenue		174		497		374		1,045
Coal Sales (Third-Party)		—		32,801		—		32,801
Coal Sales (Intercompany)		—		12,909		( 12,909 )		—
Operating Revenues	$	60,153	$	46,207	$	( 12,535 )	$	93,825

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the six months ended June 30, 2025 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	116,268	$	—	$	—	$	116,268
Capacity Revenue		29,651		—		—		29,651
Other Operating Revenue		3,221		2,723		481		6,425
Coal Sales (Third-Party)		—		68,332		—		68,332
Coal Sales (Intercompany)		—		31,971		( 31,971 )		—
Operating Revenues	$	149,140	$	103,026	$	( 31,490 )	$	220,676

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the six months ended June 30, 2024 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	92,234	$	—	$	—	$	92,234
Capacity Revenue		28,646		—		—		28,646
Other Operating Revenue		331		1,307		670		2,308
Coal Sales (Third-Party)		—		82,431		—		82,431
Coal Sales (Intercompany)		—		29,315		( 29,315 )		—
Operating Revenues	$	121,211	$	113,053	$	( 28,645 )	$	205,619

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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the three months ended June 30, 2025 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	15,617	$	—	$	6,699	$	22,316
Coal Operations — EBITDA Margin		—		2,649		( 7,382 )		( 4,733 )
Other Operating Revenue		3,134		1,399		233		4,766
Depreciation, Depletion and Amortization (1)		( 5,164 )		( 359 )		( 19 )		( 5,542 )
Asset Retirement Obligations Accretion		( 123 )		( 314 )		—		( 437 )
Exploration Costs		—		( 98 )		—		( 98 )
Gain (loss) on disposal or abandonment of assets, net		—		55		—		55
Interest Expense		( 1,891 )		( 1,928 )		—		( 3,819 )
Equity Method Investment (Loss)		—		—		197		197
Corporate — General and Administrative		—		—		( 4,457 )		( 4,457 )
Income (Loss) before Income Taxes	$	11,573	$	1,404	$	( 4,729 )	$	8,248

(1) Depreciation, Depletion and Amortization for Coal Operations includes a $ 4.8 million out-of-period adjustment resulting in decreased expense during the second quarter of 2025 due to an overestimate of depreciation, depletion and amortization expense in the first quarter 2025.

Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the three months ended June 30, 2024 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	11,425	$	—	$	12,796	$	24,221
Coal Operations — EBITDA Margin		—		( 2,777 )		( 12,909 )		( 15,686 )
Other Operating Revenue		174		497		374		1,045
Depreciation, Depletion and Amortization		( 4,698 )		( 8,930 )		( 21 )		( 13,649 )
Asset Retirement Obligations Accretion		( 113 )		( 286 )		—		( 399 )
Exploration Costs		—		( 47 )		—		( 47 )
Gain (loss) on disposal or abandonment of assets, net		—		222		—		222
Interest Expense		( 186 )		( 3,188 )		( 361 )		( 3,735 )
Loss on Extinguishment of Debt		—		—		( 1,937 )		( 1,937 )
Equity Method Investment (Loss)		—		—		( 257 )		( 257 )
Corporate — General and Administrative		—		—		( 2,862 )		( 2,862 )
Corporate — Other Operating and Maintenance Costs		—		—		( 131 )		( 131 )
Income (Loss) before Income Taxes	$	6,602	$	( 14,509 )	$	( 5,308 )	$	( 13,215 )

Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before

income taxes for the six months ended June 30, 2025 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	41,760	$	—	$	30,116	$	71,876
Coal Operations — EBITDA Margin		—		8,338		( 31,971 )		( 23,633 )
Other Operating Revenue		3,221		2,723		481		6,425
Depreciation, Depletion and Amortization		( 10,325 )		( 10,156 )		( 38 )		( 20,519 )
Asset Retirement Obligations Accretion		( 243 )		( 621 )		—		( 864 )
Exploration Costs		—		( 119 )		—		( 119 )
Gain (loss) on disposal or abandonment of assets, net		—		76		—		76
Interest Expense		( 3,623 )		( 3,919 )		—		( 7,542 )
Equity Method Investment (Loss)		—		—		( 39 )		( 39 )
Corporate — General and Administrative		—		—		( 7,434 )		( 7,434 )
Income (Loss) before Income Taxes	$	30,790	$	( 3,678 )	$	( 8,885 )	$	18,227

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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the six months ended June 30, 2024 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	31,323	$	—	$	30,407	$	61,730
Coal Operations — EBITDA Margin		—		( 3,982 )		( 29,315 )		( 33,297 )
Other Operating Revenue		331		1,307		670		2,308
Depreciation, Depletion and Amortization		( 9,395 )		( 19,658 )		( 39 )		( 29,092 )
Asset Retirement Obligations Accretion		( 224 )		( 574 )		—		( 798 )
Exploration Costs		—		( 117 )		—		( 117 )
Gain (loss) on disposal or abandonment of assets, net		—		246		—		246
Interest Expense		( 334 )		( 6,397 )		( 941 )		( 7,672 )
Loss on Extinguishment of Debt		—		—		( 2,790 )		( 2,790 )
Equity Method Investment (Loss)		—		—		( 506 )		( 506 )
Corporate — General and Administrative		—		—		( 5,310 )		( 5,310 )
Corporate — Other Operating and Maintenance Costs		—		—		( 223 )		( 223 )
Income (Loss) before Income Taxes	$	21,701	$	( 29,175 )	$	( 8,047 )	$	( 15,521 )

Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):


					Corporate and Other
Other Reconciliations:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Assets at June 30, 2025	$	231,774	$	156,811	$	20,928	$	409,513
Assets at December 31, 2024	$	220,477	$	144,519	$	4,124	$	369,120
Capital Expenditures at June 30, 2025	$	12,700	$	12,037	$	—	$	24,737

Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):


					Corporate and Other
Other Reconciliations:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Assets at June 30, 2024	$	220,511	$	367,807	$	6,851	$	595,169
Assets at December 31, 2023	$	208,331	$	376,387	$	5,062	$	589,780
Capital Expenditures at June 30, 2024	$	11,519	$	16,192	$	333	$	28,044

(15)	NET INCOME (LOSS) PER SHARE

The following table (in thousands, except per share amounts) sets forth the computation of basic earnings (loss) per share for the periods indicated:


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Basic earnings per common share:
Net income (loss) - basic	$	8,248	$	( 10,204 )	$	18,227	$	( 11,900 )
Weighted average shares outstanding - basic		42,619		37,879		42,798		37,026
Basic earnings (loss) per common share	$	0.19	$	( 0.27 )	$	0.43	$	( 0.32 )

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The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Diluted earnings per common share:
Net income (loss) - diluted	$	8,248	$	( 10,204 )	$	18,227	$	( 11,900 )

Weighted average shares outstanding - basic		42,619		37,879		42,798		37,026
Add: Dilutive effects of Restricted Stock Units		429		—		636		—
Weighted average shares outstanding - diluted		43,048		37,879		43,434		37,026

Diluted net income (loss) per share	$	0.19	$	( 0.27 )	$	0.42	$	( 0.32 )

(16)	CONTINGENCIES

Our Coal Operations subsidiary is party to litigation in which the plaintiffs allege violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $ 2.8 million, which was recorded in “operating expenses” on our consolidated statements of operations for the year ended December 31, 2024 and is in “accounts payable and accrued liabilities” on our condensed consolidated balance sheets at June 30, 2025.

(17)	SUBSEQUENT EVENTS

On July 1, 2025, the Company amended a third party customer’s coal supply sales agreement increasing contractual tons delivered by 0.3 million and 0.1 million, or $ 13.0 million and $ 2.6 million in revenue, for 2025 and 2026, respectively.

On July 4, 2025, the U.S. H.R.1, an act to provide for reconciliation pursuant to title II of H. Con. Res. 14. (“the OBBBA”) was enacted. The OBBBA introduces multiple tax law and other legislative changes, including modifications to income tax provisions such as domestic research and development expenses, capital expenditures, and U.S. taxation of international earnings; the repeal or acceleration of the sunset of certain tax credits under the 2022 Inflation Reduction Act and elimination of certain penalties for violations of certain regulatory credit programs. The Company is analyzing the potential impacts of this legislation on its business and does not anticipate there to be a material impact as a result.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2024 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.

We are pleased with our positive results in the second quarter, which is especially encouraging given that energy pricing and demand in the spring season is typically lower due to milder weather. During the quarter we generated $102.9 million of revenue with $17.6 million of EBITDA margin, an improvement of $9.1 million of EBITDA margin over the same period a year ago.

One of our two generating units at Merom was out of service for planned maintenance during the majority of the quarter. We benefited from higher-than-expected energy prices and consistent energy volumes from the generating unit that was in operation. We also saw positive results in our Coal Operations segment, including improvements in our coal production, operating costs and recovery metrics at our Oaktown mining complex. These improvements, in addition to the planned outage at Merom, resulted in higher coal inventory levels companywide. We expect coal inventories to decrease in the second half of 2025 based on increased coal shipments and greater energy generation at Merom now that this year’s planned outage is completed.

The Company continued its strategy of supplementing periods of weaker pricing with limited sales of firm energy. These firm energy sales help to mitigate the impacts of inconsistent weather and fluctuating energy prices and allowed us to focus on maximizing the value of Merom in a way that balances challenging periods while also giving us flexibility to capture upside opportunity in periods of elevated pricing, like we saw in June. In late June, we expanded our relationship with one of our firm energy counterparties, entering into a $35.0 million prepaid forward power sales contract with energy to be delivered at various periods throughout 2025 and 2026. In connection with this agreement, we also entered into the Third Amendment to our Credit Amendment, which moved the required Term Loan payment from October 2025 to January 2026 and adjusted various covenants to provide additional operating flexibility throughout the summer and into the fourth quarter. The prepaid funds will be used in a variety of ways, including fully cash collateralizing the outstanding $19.0 million Term Loan principal balance under the Credit Agreement and to support company operations.

Turning to our negotiations in support of a long-term power purchase agreement with a utility or data center developer, we have seen significant interest in our capacity and energy offerings throughout the quarter. Following the termination of our exclusivity agreement with a leading global data center developer, we have seen a high level of engagement from third parties, including other data center developers and utilities. Each of the interested parties brings a different perspective to the negotiations and each presents opportunities and challenges to effectively monetize our capacity and energy offerings. While we remain in contact with our original counterparty, we are encouraged by our discussions with several of these newly interested parties. We believe that the evolving energy markets, specifically as related to data center growth and favorable utility demand, as well as the favorable regulatory environment, provide the potential to leverage opportunities that simply were not available when we began the request for a proposal process last summer. The utility discussions that we are currently engaged in are intrinsically more straightforward to negotiate, can be implemented sooner and could result in greater sales volumes of energy and accredited capacity. We anticipate pricing will be around the energy curve with terms of ten years or more. As we have highlighted in previous disclosures, many of the non-utility arrangements are inherently complex and involve multiple parties, which adds time and alignment challenges to the negotiation process. Notwithstanding those challenges, returning to non-exclusive negotiations has reinforced our belief that in the end, we will forge a strategic partnership that will create significant value for years to come.

Over the last several quarters, we have highlighted our belief that the prevailing industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable resources such as wind and solar will create an unbalanced energy equation, reduce reliability and increase long-term volatility in the energy markets. It is our position that the enhanced reliability of dispatchable generation, like Merom, versus non-dispatchable generators will increase the value of the attributes of Hallador Power in the overall energy markets. In light of this, we continue to evaluate how to further enhance this value. As we have previously discussed, we are actively seeking acquisition opportunities for additional dispatchable generation, which we believe will help diversify our risk and provide opportunities to upsize strategic future

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arrangements. We believe that this approach has the potential to enhance our financial flexibility and strengthen our position in the evolving energy market.

Additionally, we see the potential of enhancing the reliability, resiliency and flexibility of Merom by adding natural gas and creating a dual fuel scenario, if and when the opportunity makes operational and financial sense. While we are still in the evaluation process, by adding the capability to co-fire with gas or coal, we believe that it could provide Hallador Power the ability to take advantage of the best fuel cost scenario and better control our operating expenses. We believe that the ability to co-fire with natural gas and/or coal will also provide increased resiliency in times where gas availability is traditionally limited, as we have seen in various winter storms across the last several years. This co-firing also allows us to retain the advantage of operating our Sunrise Coal subsidiary and leveraging our own coal supply to prevent unreasonable price increases by third party providers while simultaneously supporting our workforce and the surrounding community. This evaluation is complex on a variety of levels, specifically customer preference and an evolving regulatory environment that could have material impacts on the timing and economic benefits of undertaking such a change.

We continue to invest in the future of the plant through extensive maintenance and capital expenditures. We had one unit out of service for planned maintenance for most of the quarter and extending into early third quarter. We typically choose the shoulder season periods for these planned maintenance outages as power demand and pricing in spring are traditionally lower than in other parts of the year. We also try to limit our firm energy sales during these periods to guard against any unforeseen or forced outages, which have the potential to expose us to spot market pricing. Despite the outage, we saw stronger than expected prices in June, which we were able to take advantage of with the unit that remained online. As illustrated in the solid forward sales position table below, in 2026, we currently have 4.0 million delivered energy MWh contracted at an average sales price of $43.05 per MWh. We continue to see higher demand and increase in our average contracted sales price. Our largest PPA contract will see an increase of more than $20.00 per MWh in 2026 as compared to 2025 on expected volumes of approximately 1.6 million MWh. Following 2026, we are optimistic that we will be able to sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a strong forward curve.

We believe that Hallador is uniquely positioned to transform retiring and/or underperforming assets into future opportunities. This will enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail consumers, unlike a traditional utility siphoning off consumer power to serve these types of large load end-users. By continuing the operations of the dispatchable plants to support large load industrial users as the utilities transition to non-dispatchable generation, the new generation becomes additive to the already struggling grid rather than cannibalizing the overall reliability of what exists today. We remain optimistic about the potential to add to our strategic portfolio and the long-term benefits that such a transaction could produce for the company, its shareholders and its customers. This model for growth enables us to capture value from the critical factors limiting artificial intelligence and data center growth, accredited capacity and reliable and affordable energy. Importantly, the positive momentum that we continue to see from the current administration on both the federal and state levels should make transactions of this sort more feasible than they would have been under the prior administration.

Shifting to our Coal Operations, we continue to see the benefits of our 2024 organizational restructuring. While much of the last year was focused on optimizing production, headcount, and strategy to best support our Electric Operations and our existing third-party coal contracts, we have seen improved operational expenses, more efficient recoveries and accelerating shipments. As we have said before, this organizational restructuring should provide us with greater flexibility to quickly scale if we see coal prices increase to a point that justifies restarting production at higher cost units. Additionally, while our coal inventories are elevated, we believe that we are well-positioned to meet industry needs in the event that coal plants, including Merom, continue to dispatch at higher levels.

With renewed support of coal mining and coal fired power generation on both the federal and state level, we believe that we are well positioned to take advantage of opportunities for growth and/or expansion. Current market dynamics remain stronger than they have been in the past year, and we continue to evaluate if and when it makes sense to bring on additional coal production in the back half of 2025 and/or 2026. Starting in 2026 our average contracted sales price across all contracts is approximately $4.00 per ton higher than the average contracted sales price in 2025.

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Notwithstanding this potential to increase production, we currently expect to produce approximately 3.7 million tons of coal in 2025. In the first half of 2025, we produced approximately 2.1 million tons of coal at our Oaktown Mining Complex. We use supplemental coal from third party suppliers at Merom, typically purchased at favorable prices to help diversify self-production supply risk and to provide us additional flexibility in our sales portfolio if prices increase on the spot market. This optionality to obtain low-cost tons either internally or from third-parties while capturing upward swings in the commodity markets for coal should allow us to further maximize margins while optimizing fuels costs at Merom.

The continued transformation of Hallador from a commodity focused producer of coal to an IPP remains our primary focus, while leveraging this transition to capture the expanding margins of the energy markets and capitalize on the soaring demand for reliable electricity. The strong and varied interest that we have experienced following the end of our exclusivity period has been encouraging and we are steadfast in our belief of the value that our strategic transition in support of the economy’s desire for reliable energy will bring. We continue to believe that our business is well positioned to take advantage of opportunities for growth and cash flow generation as they arise.

Our goal is for Hallador Power to generate on average 1.5 million MWh on a quarterly basis, which equates to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below). During the first six months of the year, Hallador Power generated 2.2 million MWh, or 73.3% of our quarterly target and purchased 0.2 million MWh.


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Power Capacity and Utilization
Nameplate capacity (MW) ⁽ⁱ⁾	1,080		1,080		1,080		1,080
Accredited capacity for the period (MW) ⁽ⁱⁱ⁾	921		911		857		874
Accredited capacity utilization ⁽ⁱⁱⁱ⁾	37	%	39	%	60	%	42	%

(i).

Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.

(ii).

Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 775 MW and 829 MW per day for 2025 and 2024, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.

(iii).

Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24, times the number of days for the period.

When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million. For 2025, we have contracted approximately $56.0 million or 86.2% of our target. We believe our forward Capacity sales goals are attainable as illustrated in our “Solid Forward Sales Position” table below.

Our condensed consolidated financial statements should be read in conjunction with this discussion. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.

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OVERVIEW

The following is an overview our Electric Operations and Coal Operations for Q2 2025 compared to Q1 2025.

Q2 2025 Net Income of $8.2 million.

Electric Operations: During the second quarter of 2025, we sold 0.8 million MWh representing a 50.0% decrease in total MWh sold from Q1 2025. This decrease was expected as Q2 typically has lower demand for power and we had a planned maintenance outage on one of our units at Merom for approximately two months during the quarter. Operating revenues increased $17.53 per MWh from the first quarter of 2025. This change was primarily due to the allocation of capacity revenue over lower energy volumes.

In Q2 2025, Electric Sales were $60.0 million, or $72.44 per MWh sold, on a segment basis.

ii.

In Q2 2025, Electric Operations fuel, other operating and maintenance and cost of purchased power were $34.2 million, or $41.31 per MWh compared to $49.4 million, or $31.59 per MWh in Q1 2025. This increase in costs per MWh was due to lower energy volumes driven by the planned maintenance outage at Merom.

iii.

Q2 2025 Electric Operations income before income taxes was $13.99 per MWh, an increase of $1.72 from Q1 2025.

Coal Operations: During the second quarter of 2025, 0.9 million tons of coal were shipped on a segment basis, with approximately 0.1 million tons of that being shipped to Merom for $7.4 million. This is a decrease of 0.2 million tons of coal shipped from Q1 2025, on a segment basis. This decrease in coal shipments is mainly driven by a 70.0% reduction in shipments to Merom due to the shoulder season and lower demand for power.

In Q2 2025, Coal Operations operating revenues were $45.5 million, or $51.16 per ton, on a segment basis, an increase of $0.02 per ton from Q1 2025.

ii.

In Q2 2025, Hallador’s Coal Operations other operating and maintenance costs were $18.2 million, or $20.50 per ton, compared to $23.9 million, or $22.27 per ton, on a segment basis, in Q1 2025.

iii.

We recorded income before income taxes for the quarter of $1.58 per ton on a segment basis. This is an increase of $7.56 per ton from Q1 2025.

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II.

Solid Forward Sales Position (unaudited)


	2025		2026		2027		2028		2029		Total
Power
Energy
Contracted MWh (in millions)		2.53		4.00		1.78		1.09		0.27		9.67
Average contracted price per MWh	$	37.75	$	43.05	$	54.65	$	52.98	$	51.00
Contracted revenue (in millions)	$	95.51	$	172.22	$	97.28	$	57.75	$	13.77	$	436.53

Capacity
Average daily contracted capacity MW		716		733		623		454		100
Average contracted capacity price per MWd	$	224	$	230	$	226	$	225	$	230
Contracted capacity revenue (in millions)	$	29.46	$	61.54	$	51.40	$	37.33	$	3.47	$	183.20

Total Energy & Capacity Revenue

Contracted Power revenue (in millions)	$	124.97	$	233.76	$	148.68	$	95.08	$	17.24	$	619.73

Coal
Priced tons - 3rd party (in millions)		1.42		2.30		2.50		0.50		—		6.72
Avg price per ton - 3rd party	$	50.96	$	55.58	$	56.74	$	59.00	$	—
Contracted coal revenue - 3rd party (in millions)	$	72.36	$	127.83	$	141.85	$	29.50	$	—	$	371.54

TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED	$	197.33	$	361.59	$	290.53	$	124.58	$	17.24	$	991.27

Priced tons - Intercompany (in millions)		1.67		2.30		2.30		2.30		—		8.57
Avg price per ton - Intercompany	$	51.00	$	51.00	$	51.00	$	51.00	$	—
Contracted coal revenue - Intercompany (in millions)	$	85.17	$	117.30	$	117.30	$	117.30	$	—	$	437.07

TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT	$	282.50	$	478.89	$	407.83	$	241.88	$	17.24	$	1,428.34

●

Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $49.8 million and $39.9 million for the six months ended June 30, 2025 and 2024, respectively.

Bank debt increased by $1.0 million during the six months ended June 30, 2025. As of June 30, 2025, our bank debt was $45.0 million.

We expect cash generated from operations to primarily fund our capital expenditures and our debt service. As of June 30, 2025, we also had an additional borrowing capacity of $32.8 million.

Total liquidity as of June 30, 2025 was $42.0 million.

II.

Material Off-Balance Sheet Arrangements

Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value of reclamation obligations of $17.4 million, including $5.9 million at Merom, presented as asset retirement obligations (“ARO”) and accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.9 million to cover ARO.

CAPITAL EXPENDITURES (capex)

For the six months ended June 30, 2025, capex was $24.8 million allocated as follows (in millions):


Oaktown – maintenance capex	$	7.7
Oaktown – investment		4.4
Merom Plant		12.7
Capex per the Condensed Consolidated Statements of Cash Flows	$	24.8

RESULTS OF OPERATIONS

Presentation of Segment Information

Our operations are divided into two primary reportable segments: Electric Operations and Coal Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the Notes to the Condensed Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.

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Electric Operations


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024

	(in thousands)				(in thousands)
Delivered Energy	$	44,132	$	43,106	$	116,268	$	92,234
Capacity Revenue		15,844		16,873		29,651		28,646
Electric Sales	$	59,976	$	59,979	$	145,919	$	120,880

Fuel	$	(21,328)	$	(24,416)	$	(59,399)	$	(49,351)
Other Operating Costs (1)		(1)		7		(9)		14
Other Operating and Maintenance Costs (2)		(10,707)		(12,479)		(15,234)		(17,365)
Cost of Purchased Power		(2,172)		(2,619)		(9,012)		(4,545)
Utilities		(1,383)		(437)		(2,059)		(959)
Labor		(7,639)		(7,160)		(15,782)		(14,843)
General and Administrative		(1,129)		(1,450)		(2,664)		(2,508)
EBITDA Margin		15,617		11,425		41,760		31,323
Other Operating Revenue		3,134		174		3,221		331
Depreciation, Depletion and Amortization		(5,164)		(4,698)		(10,325)		(9,395)
Asset Retirement Obligations Accretion		(123)		(113)		(243)		(224)
Interest expense		(1,891)		(186)		(3,623)		(334)
Income before Income Taxes	$	11,573	$	6,602	$	30,790	$	21,701

(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024

	(per MWh)				(per MWh)
MWh Generated (in thousands)		754		780		2,176		1,596
MWh Purchased (in thousands)		74		59		216		134
MWh Sold (in thousands)		828		839		2,392		1,730

Delivered Energy	$	53.30	$	51.38	$	48.61	$	53.31
Capacity Revenue		19.14		20.11		12.40		16.56
Electric Sales	$	72.44	$	71.49	$	61.01	$	69.87

Fuel	$	(25.76)	$	(29.10)	$	(24.83)	$	(28.53)
Other Operating Costs (1)		—		0.01		—		0.01
Other Operating and Maintenance Costs (2)		(12.93)		(14.87)		(6.37)		(10.04)
Cost of Purchased Power		(2.62)		(3.12)		(3.77)		(2.63)
Utilities		(1.67)		(0.52)		(0.86)		(0.55)
Labor		(9.23)		(8.53)		(6.60)		(8.58)
General and Administrative		(1.36)		(1.73)		(1.11)		(1.45)
EBITDA Margin		18.87		13.63		17.47		18.10
Other Operating Revenue		3.79		0.21		1.35		0.19
Depreciation, Depletion and Amortization		(6.24)		(5.60)		(4.32)		(5.43)
Asset Retirement Obligations Accretion		(0.15)		(0.13)		(0.10)		(0.13)
Interest expense		(2.28)		(0.22)		(1.51)		(0.19)
Income before Income Taxes	$	13.99	$	7.89	$	12.89	$	12.54

(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

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Q2 2025 vs. Q2 2024

Delivered Energy revenue on a dollar and per MWh basis remained flat quarter over quarter, however MWh generated decreased 0.1 million or 3.3% and MWh purchased increased 0.1 million MWh or 25.4% during the same periods. When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market, which we record as cost of purchased power. Cost of purchased power in Q2 2025 was $2.2 million at an average purchase price of $29.35 MWh compared to $2.6 million at an average price of $44.39 per MWh in Q2 2024.

Fuel costs decreased $3.1 million, or 12.6%, compared to the second quarter of 2024. On a per MWh basis, fuel costs decreased $3.34, or 11.5%. This change was due to decreased production of energy as noted above resulting in 0.1 million tons or 11.4% less tons of coal used. The average purchase price per ton of coal used in the plant on a segment basis, was $53.38 in the second quarter of 2025, decreasing from $54.17 per ton in the second quarter of 2024.

Other operating revenue increased $3.0 million, or 1701.1%, compared to Q2 2024. Other operating revenue on a per MWh basis increased $3.58, or 1704.8%. This change was due to revenue received related to contractual negotiations on the exclusivity agreement.

Electric interest expense increased $1.7 million, or 916.7%, compared to the second quarter of 2024. On a per MWh basis, interest expense increased $2.06, or 936.4%. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024 and June 2025.

Income before income taxes increased $5.0 million, or 75.3%, compared to the second quarter of 2024. The main drivers of this change in income before income taxes are described in the discussion above.

YTD 2025 vs. YTD 2024

Delivered energy increased $24.0 million, or 26.1%, compared to the first six months of 2024. This increase is attributable to new PPA contracts starting in Q1 2025 that were not in effect during 2024. Total PPA hours delivered in the first six months of 2025 were 1.8 million at an average price of $36.63 per MWh compared to delivery of 1.0 million MWh at an average price of $34.42 for the same period in 2024.

Fuel increased $10.0 million, or 20.4%, compared to the first six months of 2024. The increase in fuel costs were directly related to the increase in MWh generated, requiring the increased use of fuel by 0.2 million tons of coal or 21%. On a per MWh basis, fuel decreased $3.70, or 13.0% at an average cost of $53.65 per ton for 2025 compared to an average cost of $55.80 per ton for 2024.

The cost of purchased power increased $4.5 million, or 98.3%, compared to year-to-date 2024. On a per MWh basis, cost of purchased power increased $1.14, or 43.3%. When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market, which we record as cost of purchased power.

Electric interest expense increased $3.3 million, or 984.7%, compared to the first six months of 2024. On a per MWh basis, interest expense increased $1.32, or 694.7%. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024 and June 2025.

Income before income taxes increased $9.1 million, or 41.9%, compared to the first six months of 2024. The main drivers of this change in income before income taxes are described in the discussion above.

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Coal Operations


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024

	(in thousands)				(in thousands)
Coal Sales	$	45,529	$	45,710	$	100,303	$	111,746

Fuel	$	(434)	$	(750)	$	(990)	$	(1,985)
Other Operating and Maintenance Costs		(18,247)		(21,597)		(42,101)		(53,388)
Utilities		(3,124)		(3,253)		(6,600)		(7,545)
Labor		(19,160)		(19,395)		(38,046)		(46,880)
General and Administrative		(1,915)		(3,492)		(4,228)		(5,930)
EBITDA Margin		2,649		(2,777)		8,338		(3,982)
Other Operating Revenue		1,399		497		2,723		1,307
Depreciation, Depletion and Amortization		(359)		(8,930)		(10,156)		(19,658)
Asset Retirement Obligations Accretion		(314)		(286)		(621)		(574)
Exploration Costs		(98)		(47)		(119)		(117)
Gain on disposal or abandonment of assets, net		55		222		76		246
Interest expense		(1,928)		(3,188)		(3,919)		(6,397)
Income (Loss) before Income Taxes	$	1,404	$	(14,509)	$	(3,678)	$	(29,175)


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024

	(per ton)				(in thousands)
Tons Sold		890		849		1,961		2,063

Coal Sales	$	51.16	$	53.84	$	51.15	$	54.17

Fuel	$	(0.49)	$	(0.88)	$	(0.50)	$	(0.96)
Other Operating and Maintenance Costs		(20.50)		(25.44)		(21.47)		(25.88)
Utilities		(3.51)		(3.83)		(3.37)		(3.66)
Labor		(21.53)		(22.84)		(19.40)		(22.72)
General and Administrative		(2.15)		(4.11)		(2.16)		(2.87)
EBITDA Margin		2.98		(3.27)		4.25		(1.93)
Other Operating Revenue		1.57		0.59		1.39		0.63
Depreciation, Depletion and Amortization		(0.40)		(10.52)		(5.18)		(9.53)
Asset Retirement Obligations Accretion		(0.35)		(0.34)		(0.32)		(0.28)
Exploration Costs		(0.11)		(0.06)		(0.06)		(0.06)
Gain on disposal or abandonment of assets, net		0.06		0.26		0.04		0.12
Interest expense		(2.17)		(3.76)		(2.00)		(3.10)
Income (Loss) before Income Taxes	$	1.58	$	(17.09)	$	(1.88)	$	(14.14)

Q2 2025 vs. Q2 2024

Other operating and maintenance costs decreased $3.4 million, or 15.5%, compared to the second quarter of 2024. On a per ton basis other operating and maintenance costs decreased $4.94, or 19.4%. This change was the result of impacts related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as increased coal production of 0.2 million tons or 19.1% in Q2 2025 over Q2 2024 whereas coal sales increased 0.1 million tons or 4.8% increasing coal inventory.

General and administrative costs decreased $1.6 million, or 45.2%, compared to the second quarter of 2024. On a per ton basis general and administrative costs decreased $1.96, or 47.7%. This change was related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as the retirement of an executive officer in 2024.

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Depreciation, depletion and amortization decreased $8.6 million, or 96.0%, compared to the second quarter of 2024. On a per ton basis, depreciation, depletion and amortization decreased $10.11, or 96.2%. This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as a $4.8 million out-of-period adjustment recorded during the second quarter of 2025 due to an overestimate of depreciation, depletion and amortization expense in the first quarter 2025.

Interest expense decreased $1.3 million, or 39.5%, compared to the second quarter of 2024. On a per ton basis, interest expense decreased $1.59, or 42.3%. Our decreased interest expense relates to reductions of convertible debt of $11.0 million and related party debt of $5.0 million.

Income before income taxes increased $15.9 million, or 109.7%, compared to the second quarter of 2024. The main drivers of this change in loss before income taxes are described in the discussion above.

YTD 2025 vs. YTD 2024

Coal sales decreased $11.4 million, or 10.2%, compared to the first six months of 2024. On a per ton basis, coal sales decrease $3.02, or 5.6%. Consolidated coal sales decreased $14.1 million, or 17.1% from 2024. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $2.99 per ton and we sold 0.1 million tons less compared to 2024. Our average sales price, on a consolidated basis for 2025 decreased $4.27 per ton and we sold 0.2 million tons less compared to 2024.

Other operating and maintenance costs decreased $11.3 million, or 21.1%, compared to the first six months of 2024. On a per ton basis, other operating and maintenance costs decreased $4.41, or 17.0%. This change was partially the result of the organizational restructuring that occurred in February 2024 extending into Q2 2024 which led to an expected reduction in production costs related to the higher cost mining locations such as roof support and maintenance. Tons sold decreased 0.1 million tons or 4.9% which further decreased royalty expenses.

Labor decreased $8.8 million, or 18.8%, compared to the first six months of 2024. On a per ton basis, labor decreased $3.32, or 14.6%. This change was the result of the organizational restructuring that occurred in February 2024 which reduced the Coal Operations headcount to 655 as of June 30, 2025 from 924 prior to the restructuring.

General and administrative costs decreased $1.7 million, or 28.7%, compared to the first six months of 2024. On a per ton basis, general and administrative decreased $0.72, or 25.0%. This change was related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as the retirement of an executive officer in 2024.

Other operating revenue increased $1.4 million, or 108.3%, compared to the first six months of 2024. On a per ton basis, other operating revenue increased $0.76, or 119.2%. This change was the result of increased utilization of our rail facility by a customer resulting in an increase in transloading fee revenue.

Depreciation, depletion and amortization costs decreased $9.5 million, or 48.3%, compared to the first six months of 2024. On a per ton basis, depreciation, depletion and amortization decreased $4.35, or 45.6%. This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million.

Interest expense decreased $2.5 million, or 38.7%, compared to the first six months of 2024. Interest expense on a per ton basis decreased $1.10, or 35.6%. Our decreased interest expense primarily relates to reductions of convertible debt of $11.0 million and related party debt of $5.0 million.

Loss before income taxes decreased $25.5 million, or 87.4%, compared to the first six months of 2024. The main drivers of this change in loss before income taxes are described in the discussion above.

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Quarterly coal sales and cost data on a segment basis are as follows (in thousands, except per ton data and wash plant recovery percentage):


All Mines	3rd 2024			4th 2024			1st 2025			2nd 2025			T4Qs
Tons produced		873			971			1,020			1,059			3,923
Tons sold		926			875			1,071			890			3,762
Wash plant recovery in %		60	%		62	%		64	%		66	%
Capex (Coal Operations)	$	6,810		$	11,079		$	6,244		$	5,793		$	29,926
Maintenance capex (Coal Operations)	$	4,208		$	4,492		$	4,000		$	3,691		$	16,391
Maintenance capex per ton sold (Coal Operations)	$	4.54		$	5.13		$	3.73		$	4.15		$	4.36

Average cost per ton sold⁽ⁱ⁾	$	52.22		$	43.25		$	43.65		$	46.03


All Mines	3rd 2023			4th 2023			1st 2024			2nd 2024			T4Qs
Tons produced		1,594			1,331			1,271			889			5,085
Tons sold		2,054			1,461			1,214			849			5,578
Wash plant recovery in %		65	%		62	%		60	%		59	%
Capex (Coal Operations)	$	11,570		$	17,867		$	8,632		$	7,560		$	45,629
Maintenance capex (Coal Operations)	$	7,938		$	13,567		$	8,085		$	6,014		$	35,604
Maintenance capex per ton (Coal Operations)	$	3.86		$	9.29		$	6.66		$	7.08		$	6.38

Average cost per ton sold⁽ⁱ⁾	$	46.54		$	53.78		$	51.65		$	49.94

(i) Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”, “Utilities” and “Labor” costs. Coal Operations costs are presented in the “Presentation of Segment Information” above.

Presentation of Consolidated Information

EARNINGS (LOSS) PER SHARE


	3rd 2024		4th 2024		1st 2025		2nd 2025
Basic	$	0.04	$	(5.06)	$	0.23	$	0.19
Diluted	$	0.04	$	(5.06)	$	0.23	$	0.19


	3rd 2023		4th 2023		1st 2024		2nd 2024
Basic	$	0.49	$	(0.31)	$	(0.05)	$	(0.27)
Diluted	$	0.44	$	(0.31)	$	(0.05)	$	(0.27)

INCOME TAXES

Our effective tax rate (ETR) is estimated at ~0% and ~23% for the six months ended June 30, 2025 and 2024, respectively. For the six months ended June 30, 2025, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

RESTRICTED STOCK GRANTS

See “Item 1. Financial Statements - Note 9 - Stock Compensation Plans” for a discussion of RSUs.

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CRITICAL ACCOUNTING ESTIMATES

We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, and the estimates used in impairment analysis are our critical accounting estimates.

The reserve estimates are used in the depreciation, depletion, and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal.

SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.

Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.

Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant.

Inventory is valued at a lower of cost or net realizable value (NRV). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of June 30, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively.

Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. Management evaluates

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assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

No material changes from the disclosure in our 2024 Annual Report on Form 10-K .

ITEM 4. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS

We maintain a system of disclosure controls and procedures that are designed for the purpose of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our CEO and CFO and as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective.

There have been no changes to our internal control over financial reporting during the quarter ended June 30, 2025, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

●

changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position;

●

fluctuations in weather, gas and electricity commodity costs, inflation and economic conditions impact demand of our customers and our operating results;

●

the outcome or escalation of current hostilities in Ukraine and Israel;

●

changes in competition in electricity or coal markets and our ability to respond to such changes;

●

changes in coal prices, demand, and availability which could affect our operating results and cash flows;

●

risks associated with the expansion of our operations and properties;

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●

legislation, regulations, administrative actions (e.g., Executive Orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases, mining, miner health and safety, and health care, as well as those relating to data privacy protection;

●

deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;

●

dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts;

●

changing global economic conditions or the geopolitical environment in industries in which our customers operate;

●

anticipated changes in the U.S. political environment, including those resulting from the change in Presidential Administration and control of Congress, and to regulatory agencies;

●

changes in attitude toward environmental, social, and governance (“ESG”) matters among regulators, investors and parties with which we do business;

●

the effect of changes in taxes or tariffs and other trade measures;

●

risks relating to inflation and increasing interest rates;

●

liquidity constraints, including due to restrictions contained in our indebtedness and those resulting from any future unavailability of financing;

●

customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, or other failures to perform;

●

customer delays, failure to take coal under contracts or defaults in making payments;

●

adjustments made in price, volume or terms to existing coal supply and customer agreements;

●

our productivity levels and margins earned on our coal or electricity sales;

●

supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures;

●

changes in the availability of skilled labor;

●

our ability to maintain satisfactory relations with our employees;

●

increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers’ compensation claims;

●

increases in transportation costs and risk of transportation delays or interruptions;

●

operational interruptions due to geologic, permitting, labor, weather-related or other factors;

●

risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control;

●

results of litigation, including claims not yet asserted;

●

difficulty maintaining our surety bonds for mine reclamation;

●

decline in or change in the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels;

●

risks resulting from climate change or natural disasters;

●

difficulty in making accurate assumptions and projections regarding post-mine reclamation;

●

uncertainties in estimating and replacing our coal reserves;

●

the impact of current and potential changes to federal or state tax rules and regulations, including a loss or reduction of benefits from certain tax deductions and credits;

●

difficulty obtaining commercial property insurance;

●

evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;

●

difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control;

●

any future pandemics and their impacts, both in their intrinsic severity and in the political and social responses to them, which could affect, among other things, our operations and personnel, the demand for coal, the financial condition of our customers and suppliers and available liquidity and capital; and

●

other factors, including those discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K.

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If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “ Item 1A. Risk Factors ” in our Annual Report on Form 10-K. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law.

You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

PART II - O T H E R INFORMATION

ITEM 4. MINE SAFETY DISCLOSURES

See Exhibit 95.1 to this Form 10-Q for a listing of our mine safety violations.

ITEM 6. EXHIBITS


Exhibit No.		Document
10.1		Offer Letter, dated June 1, 2025, by and between Todd Telesz and Hallador Energy Company
10.2		Separation and Release Agreement, dated June 29, 2025, by and between Marjorie Hargrave and Hallador Energy Company
10.3		Third Amendment to the Fourth Amended and Restated Credited Agreement, dated as of August 2, 2023
10.4		Hallador Energy Company Second Amended and Restated 2008 Restricted Stock Unit Plan (incorporated by reference to Appendix A of the Proxy Statement filed with the Securities and Exchange Commission on April 17, 2025)
31.1		SOX 302 Certification - Chief Executive Officer
31.2		SOX 302 Certification - Chief Financial Officer
32		SOX 906 Certification
95.1		Mine Safety Disclosures
101.INS		Inline XBRL Instance Document
101.SCH		Inline XBRL Schema Document
101.CAL		Inline XBRL Calculation Linkbase Document
101.LAB		Inline XBRL Labels Linkbase Document
101.PRE		Inline XBRL Presentation Linkbase Document
101.DEF		Inline XBRL Definition Linkbase Document
104		Cover Page Interactive Data File (embedded with the Inline XBRL document)

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	HALLADOR ENERGY COMPANY

Date: August 11, 2025	/s/ TODD E. TELESZ
	Todd E. Telesz, CFO (Principal Financial Officer and Principal Accounting Officer)

TABLE OF CONTENTS

Part I - Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II - Other Information Item 4. Mine Safety Disclosures Item 6. Exhibits

Exhibits

10.1 Offer Letter, dated June 1, 2025, by and between Todd Telesz and Hallador Energy Company 10.2 Separation and Release Agreement, dated June 29, 2025, by and between Marjorie Hargrave and Hallador Energy Company 10.3 Third Amendment to the Fourth Amended and Restated Credited Agreement,dated as of August 2, 2023 31.1 SOX 302 Certification - Chief Executive Officer 31.2 SOX 302 Certification - Chief Financial Officer 32 SOX 906 Certification 95.1 Mine Safety Disclosures

HNRG 10-Q Quarter ended June 30, 2025

Exhibits